Eugene Island Block Research Articles

Quantitative analysis of slip-induced dilation with application to fault seal

A new quantitative model for calculating the volumes and rates of fault-zone fluid migration during dynamic slip events is developed. This model is based on observations from laboratory rock mechanics experiments of porosity evolution during frictional sliding and geophysical data that demonstrate the existence of propagating slip pulses that experience transient dilation during earthquakes. The nature of dilation during slip is dependent on the frictional behavior; that is, whether the fault experiences seismic or aseismic slip. The transient dilation that occurs during seismic slip is more efficient in transporting fluids along the fault than the relatively reduced dilation that occurs during aseismic slip. For aseismic faults, fluid-migration rates are primarily dependent on the intrinsic permeability structure of the fault rock during periods of no slip (static permeability). In contrast, both the static and dynamic permeabilities are important along faults that slip seismically. We infer that aseismic slip does not enhance migration significantly other than providing a transient, spatially restricted permeability increase that may act to initiate migration. The proposed models are applied to estimate the maximum amounts of hydrocarbon leakage from seismically active faults that trap hydrocarbons in the Cusiana field, Colombia, and aseismic faults at Eugene Island Block 330 field, Gulf of Mexico. Model results are grossly consistent with observed hydrocarbon volumes and inferred along-fault migration rates from the two areas. The proposed models have broad implications for understanding the effects of faults on fluid migration during both exploration (geologic) and production time scales.

Multifarious VSP methods for imaging of complex structures with three component data

Yingping Li, Baker Atlas, Dorothea Faw, Ocean Energy, James Jackson, David Dushman, Fran Doherty, Baker Atlas provide a case study of the benefits of modern borehole seismic technology in the Gulf of Mexico In the US Gulf of Mexico, petroleum reserves are often trapped underneath overhangs of diapiric salt domes. Although the top of salt and sediment structures can be well imaged using current surface seismic migration techniques, the interpretation of the salt flank with irregularly shaped overhangs and the position of updip sands is often ambiguous. Therefore, vertical seismic pro-filing (VSP) surveys are usually requested for additional, independent information (Sparlin and Deri, 1989; Millahn and Manzur, 1990; Nosal et al, 1991; Barker and Guzman, 1992; Burch and Johnson, 1993). The area under study is located in Eugene Island Block 126. There was a deviated well drilled to 11 794 ft SS in the vicinity of a salt dome. A comprehensive borehole seismic survey was designed and acquired in this well in order to obtain a better image of the updip sands and the salt flank. The multifarious three component (3C) VSP data consisted of a rig-source velocity survey (VS), an offset VSP (OVSP), and a refraction salt proximity survey (SP). A map view of the VSP survey configuration is shown in Figure 3. The blue circles are source locations and the pink triangles represent the well trajectory. The survey source was a 500 in, 3 fourgun tuned airgun array. A DGPS navigation system was used to ensure that all sources were in the correct position. To reliably estimate arrival directions for the SP, a gyro tool was attached to the 3C geophone and was used to monitor the orientation of the horizontal geophone components. The rig-source VS was acquired to accurately measure the sediment velocities needed for processing the OVSP and SP data. The data were also subsequently used for ray-trace modelling. The 3C OVSP was shot at an offset of 5571 ft from the wellhead. Presurvey modelling indicated the optimal position of the source to produce reflection images for both the salt face and the updip reservoir sands flanking the salt. The source location of the SP was positioned over the salt top at an offset of 5404 ft from the wellhead. The SP source was positioned in order to utilize the refracted waves to define a salt face position by calculating salt exit points in 3D space. In this paper, we present VSP imaging results from the multifarious VSP survey in the Eugene Island field. The OVSP reflection image of the salt face closely matches the salt exit points calculated from the 3D SP. The determined salt boundary is also consistent with existing well control data. The sedimentary reflectors from the OVSP data terminate as they approach the salt face. Post-survey travel time modelling of the SP data and the salt lead from the VS data provided a further constraint on the shape of the salt flank. Both the refraction and reflection images can be integrated with other available information such as well control data, results from ray-trace modelling, and surface-seismic data, to produce a consistent image of the salt face and the target sand beds. Careful processing and interpretation of the various VSP data result in the precise definition of a diapiric salt dome and updip sands in the Eugene Island field.

Wave-equation migration of common-receiver gathers for AVO analysis

During the 1980s and 1990s, we developed a number of recursive wave-equation algorithms for prestack depth migration in the shot domain. Much of that work was driven by development of the vertical-cable recording technique. However, we applied the algorithms to image a variety of 2D and 3D land and marine surveys. Virtually all of those projects were oriented toward obtaining better structural images and without concern for preserving relative amplitude information. Increasing interest in prestack amplitude analysis of migrated data led us to revisit that decision and to evaluate the possibility of analyzing AVO (or AVA) within image gathers. Developers of other wave-equation-based algorithms have presented similar evaluations and have achieved useful results. However, our production algorithms are sufficiently different that the applicability of their results to our project work is not clear. Consequently, we decided to conduct our own study, starting with a modeling-based approach—rather than a theoretical one—to analyze application of one of our 3D shot-record depth migration algorithms to synthetic and real data. The immediate value of this would be as a measure of the “amplitude-friendliness” of an existing production algorithm under specific conditions. Beyond that, it would help us gauge the potential value of allocating additional theoretical and/or development work to enhance its usefulness as a tool for amplitude studies in projects involving wave-equation shot-record migration. The real data set we selected for testing is an OBC survey recorded by Texaco in 1997 at Teal South Field (Eugene Island Block 354) in the Gulf of Mexico. This survey was used 24 4C receiver groups fixed in a sparse pattern on the seafloor, about 82 m deep (Figure 1). The source was a small air-gun array towed at a depth of 3 m and was deployed at locations on a finer (nominally 25 × 25 m) grid …

Reservoir fluids and their migration into the South Eugene Island Block 330 reservoirs, offshore Louisiana

This study in the well-documented Pliocene-Pleistocene South Eugene Island Block 330 (SEI330) field, offshore Louisiana, unravels a complex petroleum system by evaluating both the inorganic and organic geochemical characteristics of reservoir fluids. The brines at SEI330 dissolved halite prior to entering the reservoirs and equilibrated with reservoir sediments, exchanging sodium for calcium, magnesium, and other cations. The systematically varying extent of brine sodium depletion in two reservoirs defines south to north flow in those sands. These sands were filled from a fault that bounds the reservoirs on the south. Oil compositional parameters also show north-south variation across these reservoirs. The SEI330 oils and gases each had different sources. In contrast to published Jurassic sources for oil, carbon isotope data indicate that SEI330 hydrocarbon gases probably sourced from early Tertiary or Cretaceous sediments, after oil had migrated through them. Distribution of biodegraded vs. unbiodegraded oils indicates the reservoirs filled much more recently than formation of the salt weld beneath the field. Oil compositions indicate that some SEI330 oils were partially stripped of low-molecular weight compounds by their dissolution in a mobile vapor phase (gas washed) by large volumes of gas several hundred meters below the deepest reservoir. Modeling of this gas-oil interaction aids in identifying deep potential targets in which gas washing occurred. Hydrocarbon distribution, combined with oil chemistry and reservoir pressures, indicate reservoirs filled from fault systems on both the north and south sides of the field. The fault feeders are wide (>100 m), structurally complex zones that can direct different types of fluids into different reservoirs.

Seismic time-lapse surprise at Teal South: That little neighbor reservoir is leaking!

Why perform time-lapse seismic monitoring? Is it to verify the reservoir model? No! We should conduct time-lapse seismic surveys in order to find out what is incorrect in the reservoir model, in a way similar to the production history matching familiar to reservoir engineers as they look for improvements to the model. This being the case, it is difficult to determine in advance of monitoring just what it is we should be monitoring. Thus, surveys designed specifically to test one feature of a reservoir model may be missing other important features. In this paper, we present a set of very surprising results from the Teal South time-lapse multicomponent (4-D/4-C) study, in Eugene Island Block 354 in the Gulf of Mexico. We will show that time-lapse seismic observations have revealed that an undrilled reservoir near a producing reservoir is exhibiting time-lapse changes consistent with expansion of a free gas phase, and that this implies that oil is being lost through the spill point, never to be recovered, ev...

Short-time-scale (year) variations of petroleum fluids from the U.S. Gulf Coast

Evolving short-term (less than 5 yr) compositional changes in hydrocarbon charge from some Eugene Island Block 330 (EI-330) wells are demonstrated. Storage, analytical, and production artifacts are shown to be minimal. In some wells, compositions remain constant from 1985 to 1993, whereas in others in the same reservoir, significant changes are observed. In some cases, temporal variability is greater than spatial variability. Maximum temporal change is strongest for specific compounds: toluene and C6 to C9 normal alkanes, but is also observed to a lesser extent for higher-molecular-weight components (up to n-C32). Principal coordinate analysis shows the highest degree of overall temporal compositional change over an 8-yr period in the shallowest wells where there is also evidence of biodegradation. Small temporal compositional changes are also observed in two deeper wells that are below the thermal window favorable for biodegradation. An exception is an unusual oil, where a very large increase in toluene, as well as smaller changes in a number of n-alkanes, was observed in 1993. The δ13C compound-specific isotopic signature of toluene, in addition to several other C7-C8 compounds in this oil, yields convincing evidence that it is related to the same family as other EI-330 oils and unlikely to be due to a drilling or laboratory contaminant. Minor isotopic differences in other C7 compounds (1.5‰) are consistent with extensive gas washing of this oil. The short-term compositional changes in EI-330 oils are attributed to gas washing, which causes overprinting of biodegraded oils with light n-alkanes in shallower GA and HB reservoirs where oils are currently being biodegraded in situ. Patterns of smaller changes in heavier compounds in both shallower and deeper wells are also consistent with this interpretation.

A fully 3D adaptive finite element simulation and prototype for gas flow in a porous media

This paper presents a three-dimensional (3D) adaptive finite element solution for gas flow in a porous media. The solution obtained is truly 3D and employs a dynamic h-adaptive refinement technique for efficiency. The adaptive procedure uses a new node-based storage mechanism [Wang GH, Tyler JM, Weltman JS, Callahan JD. Advances in Engineering Software including Computing Systems in Engineering 1999;30:31–41]. This node-based structure substantially reduces the memory necessary to store the finite element mesh. A prototype simulator, written in C++, has been implemented for Eugene Island block 305, a multi-well condensate reservoir off the coast of Louisiana to demonstrate the use of this adaptive procedure. Results, presented in this paper, show dramatic agreement with the actual production data. This prototype simulator uses Windows workstations to support a fully dynamic 3D mesh plus mesh generation.

Vertical and Lateral Fluid Flow Related to a Large Growth Fault, South Eugene Island Block 330 Field, Offshore Louisiana

Data from sediments in and near a large growth fault adjacent to the giant South Eugene Island Block 330 field, offshore Louisiana, indicate that the fault has acted as a conduit for fluids whose flux has varied in space and time. Core and cuttings samples from two wells that penetrated the same fault about 300 m apart show markedly different thermal histories and evidence for mass flux. Sediments within and adjacent to the fault zone in the U.S. Department of Energy-Pennzoil Pathfinder well at about 2200 m SSTVD (subsea true vertical depth) showed little paleothermal or geochemical evidence for throughgoing fluid flow. The sediments were characterized by low vitrinite reflectances (Ro), averaging 0.3% Ro, moderate to high d18O and d13C values, and little difference in major or trace element composition between deformed and undeformed sediments. In contrast, faulted sediments from the A6ST well, which intersects the A fault at 1993 m SSTVD, show evidence for a paleothermal anomaly (0.55% Ro) and depleted d18O and d13C values. Sodium is depleted and calcium is enriched in a mudstone gouge zone at the top of the fault cut in the well; this effect diminishes with distance from this gouge zone. Cuttings from other wells in South Eugene Island Block 330 show slightly elevated vitrinite reflectance in fault intercepts relative to sediments outside the fault zone. Overall, indicators of mass and heat flux indicate the main growth fault zone in South Eugene Island Block 330 has acted as a conduit for ascending fluids, although the cumulative fluxes vary along strike. This conclusion is corroborated by oil and gas distribution in downthrown sands in Blocks 330 and 331, which identify the fault system in northwestern Block 330 as a major feeder. Simple modeling of coupled heat and mass flux indicates the paleothermal anomaly in the fault zone intersected by A6ST well was short-lived, having a duration less than 150 yr. The anomaly could have been produced by a 2 ´ 106 m3 pulse of fluid ascending the fault at an actual velocity of over 1 km/yr (Darcy flux of 330 m/yr) from 3 km deeper in the basin. Simple Darcy law computation indicates a transient fault permeability on the order of 110 md during this flow. Pulsing of fluid up the fault was probably the norm, although most flow did not produce such strong thermal anomalies as the one detected in the A6ST well. Analysis of fluid pressures shows that the main fault is a profound lateral permeability barrier having up to 1800 psi of water pressure differential across it. The hydrocarbon sealing capacity of the fault depends on the pressure difference across the fault. Fault permeability is best understood in terms of effective stress. Under ambient conditions, the fault is at high pressure relative to downthrown reservoirs. A pulse of high-pressure fluid ascending End page 244---------------- the fault lowers effective stress in the fault zone sufficiently to produce a significant transient increase in permeability. If the fluid is in an area of the fault adjacent to downthrown, relatively low pressure reservoir sands, the fluid will discharge into them. Permeability in and adjacent to the fault then decreases, such that fluid cannot reenter the fault zone and escape from the reservoir.

Applied palaeontology: a critical stratigraphic tool in Gulf of Mexico exploration and exploitation

Abstract Recent exploration has relied heavily on detailed biostratigraphic correlations using foraminifera and calcareous nannoplankton, particularly in salt flank positions poorly imaged by seismic. Shell’s Bonnie, a deep near-salt well, was drilled at Eugene Island Block 95 to the depth of projected amplitude anomalies without encountering significant sand bodies. Detailed palaeontological correlation to nearby wells verified that the objective section had been penetrated. Objective sands were interpreted to be missing because of stratigraphic thinning on to the dome. A sidetrack well encountered significant hydrocarbon reserves. Appraisal drilling in the Mars basin (Mississippi Canyon blocks 763, 806 and 807) was aided by the recognition of regional condensed sections between gravity-flow units providing correlation of individual reservoir units within the field. Biostratigraphy showed stratigraphic pinch-out of reservoir sands rather than absence from erosional or structural truncation near vertical salt faces. The interpretation improved volume estimates and the planning of future wells.

4-C/4-D at Teal South

In late 1996, Texaco and Input/Output embarked on a novel experiment to test a low‐cost 4-C/4-D permanent reservoir monitoring system (PRMS). Western Geophysical and Digicourse were brought into the project to provide data acquisition and positioning services. In July and August 1997, four‐component (4-C) data acquisition was performed over 9 km2 in Eugene Island Block 354 (Teal South), using a dense shot grid (25×25 m). In late 1997, Texaco turned control of the project over to the Energy Research Clearing House and invited industry participation. The consortium remains open to new members.

Phase fractionation at South Eugene Island Block 330

Persistent gas flux can dissolve, remobilize and alter reservoired or migrating oil through a process of phase fractionation. Moving gas, when flowing through an oil, can dissolve large fractions of that oil. The composition of the oil dissolved in the gas is dependent on the pressure-temperature conditions of the oil and the fluid flow history of the basin. The composition of the residual oil can be interpreted to yield both the depth at which the oil fractionated and the volume of gas required to fractionate the oil. South Eugene Island Block 330 in the U.S. Gulf Coast is a hydrocarbon province that has recently experienced large gas fluxes. Some of the oils in the region show signs of progressive fractionation and remobilization by gas transport. For example, the oils are more aromatic and less paraffinitic than unfractionated oils of similar maturity from the same area. The altered oils are also depleted of light n-alkanes. We have developed a computer-based model of oil alteration based on a fluid phase equilibria algorithm to simulate progressive fractionation of oil by gas. Application of the model to the South Eugene Island Block 330 area shows that several of the oils in the area have compositions that are compatible with alteration caused by equilibrating with approximately 12 to 14 mol of gas per mol of oil (2 to 2.7 g of gas per g of EI oil). The oils appear to have fractionated at approximately the depths of their present reservoirs. The model has great potential to examine hydrocarbon fluids for evidence of past migration and mixing.

Fluid Flow in a Faulted Reservoir System: Fault Trap Analysis for the Block 330 Field in Eugene Island, South Addition, Offshore Louisiana

Reservoirs in the Eugene Island Block 330 (EI-330) field are believed to have been filled through a complex pattern of cross-fault spilling through juxtaposed sands, and possible vertical migration up associated growth faults. Fault-plane-section analysis of a major basin-bounding fault shows that given the present configuration of juxtaposed sands, cross-fault flow cannot account for the filling of most EI-330 reservoirs; however, a syntectonic process of across-fault spiral migration of hydrocarbons during active slip on the fault could account for the filling of the reservoirs. Hydrocarbons could have entered the shallow reservoirs about 0.68 Ma, before most of the present downthrown sand-on-shale traps formed. A Pennzoil three-dimensional seismic survey, shot over the highly faulted eastern anticlinal structure, enabled the detailed mapping of a buried, down-to-the-north fault and the adjacent sands. This buried fault, fault F, divides the main reservoirs of the EI-330 field into two separate fault blocks. Fault-plane-section analysis, combined with pressure and geochemical data from the two fault blocks, reveals that fault F is generally nonsealing to lateral fluid migration between juxtaposed sands of the same age. The fault is sealing to lateral fluid flow in the majority of cases where sands of different ages are juxtaposed. In one case, the capillary pressure differential between two juxtaposed sands was higher than can be attributed to permeability differences of common Gulf Coast sands, suggesting that material in the fault zone is the most likely cause of the lack of fluid flow between the juxtaposed sands.

Oil Migration in a Major Growth Fault: Structural Analysis of the Pathfinder Core, South Eugene Island Block 330, Offshore Louisiana

The Pathfinder core, collected in the South Eugene Island Block 330 field, offshore Louisiana, provides an outstanding sample of structures associated with a major growth fault that abuts a giant oil field and that is thought to have acted as a conduit for hydrocarbon migration into the producing reservoirs. Where cored, the growth-fault zone cuts semiconsolidated Pliocene-Pleistocene mudstone and is over 100 m wide. The fault zone in the core consists of three structural domains, each characterized by a distinct rock type, distribution of fault dips and dip azimuths, and distribution of spacing between adjacent faults and fractures. Although all of the domains contain oil-bearing sands, only faults and fractures in the deepest domain contain oil, even though the oil-barren fault domains contain numerous faults and fractures that are parallel to those containing oil in the deepest domain. The deepest domain is also distinguished from the other two domains by a greater degree of structural complexity and by a well-defined power-law distribution of fault and fracture spacings. Sediments in this domain behaved as competent rock with respect to fault and fracture spacing, whereas the departure from power-law distribution of fault and fracture spacing in the other two domains may reflect deformation of unconsolidated sediment. This departure from a power-law spacing distribution in the upper two domains, combined with stable isotope data that indicate low-temperature water-rock interaction within a gouge zone that separates these two fault domains, indicates that the faults in those domains may have been active only early in the history of the growth fault zone, when the sampled sediments were at shallow burial depths. Thus, these faults may predate oil migration. In contrast, the faults in the oil-bearing domain appear to have been active later in the fault zone’s history, when the sediments faulted as competent rock and when geologic and organic geochemical investigations indicate oil migrated into the Block 330 reservoirs. Even though oil is present in sands throughout the core, its restriction to faults and fractures in the youngest sampled portion of the fault zone implies that oil migrated only through that part of the fault that was active during the time when oil had access to it. The absence of oil in fractures or faults in the other, probably older, fault domains indicates that the oil was never sufficiently pressured to flow up the fault zone on its own, either by hydraulic fracture or by increased permeability as a result of decreased effective stress. Instead, fluid migration along faults and fractures in the Pathfinder core was enhanced by permeability created in response to relatively far-field stresses related to minibasin subsidence.

Seismic stratigraphy, facies architecture, and reservoir character of a Pleistocene shelf-margin delta complex, Eugene Island Block 330 Field, offshore Louisiana

The GA interval of the Eugene Island Block 330 field is the deposit of a late Pleistocene (~0.8 Ma) shelf-margin lowstand delta complex. We integrated three-dimensional (3-D) seismic, wireline log, core, and cuttings data to examine the delta's internal architecture and to reconstruct its depositional history. This interval displays a complex vertical and lateral interfingering of channel, clinoform, and base-of-slope failure deposits over short distances (a few kilometers), and is the product of delta lobe progradation and switching accompanied by syndepositional structural development (growth faults, rollover anticline) and relative sea level change. We then integrated our sequence stratigraphic interpretation with production data. Hydrocarbon accumulations in the interval are primarily associated with the updip facies (delta mouth bar, delta front) beneath the flooding surface at the top of the interval, and not the sequence boundary at the base of the interval. Maps of seismic amplitudes

Temperature, Pressure and Fluid Flow Modelling in Block 330, South Eugene Island Using 2D and 3D Finite Element Algorithms: ABSTRACT

The area centered around South Eugene Island (SEI) Block 330 consists of thin sands interlayered in shale cut by a complex network of faults bordering a salt withdrawal minibasin. The main ({open_quotes}Red{close_quotes}) fault is believed to be the feeder fault for the giant Block 330 oil field. A new 3D seismic interpretation tied to well logs and petrophysical data was used to construct 9 consistent (same number of strata and pseudowells) SW-NE cross sections depicting the geometry of the minibasin along with faults and salt. The basin evolution is modeled using a 3D Finite Element program. The kinetic model evolution accurately simulates movements across 5 representative faults and gives a reasonable history of the salt movement from 3.4 million years, when the now buried salt sill was at the sea floor. Allen-plane maps showing sand-sand connections over time can be obtained taking compaction into account. The kinetic model predicts porosity variation with time. Temperatures were calculated taking account of the dependence of the thermal conductivity on porosity, temperature and hydrocarbon saturations. The insulating effect of the Block 330 oil and gas reservoirs produces a significant positive anomaly below the reservoirs and a negative above that are similar in form tomore » those observed from bottom-hole temperature measurements.« less

Shear and Compressional Velocities of Overpressured Shales, Louisiana Offshore: Effects of Lithology and Effective Stress: ABSTRACT

Wireline and core data show how shear and compressional velocities (V[sub s] and V[sub p]) of overpressured shales from the Eugene Island Block 330 Field (Offshore Gulf of Mexico) are affected by lithology, and effective stress. From 2.1 to 2.5 km depth, V[sub p] ranges from 1750 to 2600 m/s, V[sub s] ranges from 500 to 1100 m/s, and Poisson's ratio is about 0.44. Plotting V[sub p] against V[sub s] for shales shows a strong linear trend that is close to, but different from previously defined trends. For sands, 3 different fields are distinguishable, and these can be related to fluid content, interbedding and shaliness of the sands. Compressional velocities for these deposits are primarily a function of porosity, shaliness (V[sub sh]) and effective stress. For narrow ranges of effective stress, V[sub p] increases with V[sub sh] to about V[sub sh] - 30 %, then V[sub p] decreases with increasing shaliness. As effective stress increases, V[sub p] increases for all lithologies. The trends seen in the data from these overpressured sediments also fit sediments from the stratigraphically higher, normally compacting (hydrostatically pressured) part of the section in a nearby well. About 3/4 of the overpressure is due to compaction disequilibrium,more » and the remainder is due to some other mechanism. The reduction in effective stress due to this other cause of overpressure would not have significantly affected V[sub p]. Since there is a good linear relationship between V[sub p] and V[sub s], V[sub s] would not have been significantly affected either. This raises the possibility that the high Poisson's ratio for these shales is an inherited function of depositional processes (undercompaction due to rapid fine-grained sediment accumulation).« less

Four-Dimensional Evolution of a Salt-Related Fault Network: Eugene Island Block 330 Field, Offshore Louisiana: ABSTRACT

The Eugene Island Block 330 field consists of two anticlinal rollovers in the hanging wall of a listric normal fault system that detaches along a deep salt weld. We use interpretation of well and 3D seismic data, 3D structural restoration, and fault analysis techniques to investigate the evolution of the three-dimensional geometry through time and its impact on hydrocarbon migration and entrapment. The master fault that currently forms the northeastern boundary of the field originated as two distinct, overlapping fault segments separated by a relay ramp. The segments linked by breaching of the ramp prior to 2.2 Ma. The resultant footwall splay continued to accommodate a significant proportion of the net slip, but became essentially inactive by 1.5 Ma. In the hanging wall of the master fault, interaction between two synthetic splays and an antithetic fault resulted in a similar, complex history of varying displacement distribution. Analysis of evolving hanging and footwall cutoff geometries on the various faults suggests that cross-fault hydrocarbon migration at sand-on-sand contacts may have contributed to reservoir filling. This scenario requires that Lentic (>2.2 Ma) sands in the footwall were connected to deeper hydrocarbon sources, which cannot be demonstrated and may be problematic because of themore » discontinuous nature of these sands. Moreover, the present distribution of hydrocarbons and the sealing nature of faults at some sand-on-sand contacts imply that another mechanism, such as episodic vertical migration along fault zone is required to introduce hydrocarbons into the shallow reservoirs.« less

Teamwork and geosteering pay off in horizontal project : T. Schroeder, D. Mathis, R. Howard, G. Williams & J. Sun, Oil & Gas Journal, 93(9), 1995, pp 33–39

The paper describes the well drilling of five horizontal gas wells in the Eugene Island Block 295, offshore Louisiana. The field came into production in 1973. As of 1 January 1994, the cumulative production had been approximately 2.9 million bbl of oil and condensate and 386 billion cu ft of natural gas. A project was undertaken to develop three very shallow gas sands at about 1,200, 1,800, and 2,500 feet. The paper describes the mud system, casing program, directional program, horizontal program, MWD logging, and initial production test results.

In-Situ Stress and Rock Strength in the GBRN/DOE Pathfinder Well, South Eugene Island, Gulf of Mexico

The authors present a relatively simple technique to constrain in-situ stress and effective rock strength from observations of wellbore failure in inclined wells. Application of this technique in the Global Basins Research Network (GBRN)/DOE Pathfinder well demonstrated that (1) the azimuth of S{sub h min} is {approx} N42{degree}E, perpendicular to a major growth fault penetrated by the well; (2) the magnitude of S{sub H max} is relatively close to the vertical stress; and (3) the effective in-situ compressive rock strength is 3,500 to 4,000 psi. They show that once they have estimated in-situ stress and rock strength, it is possible to compute the mud pressure required to inhibit failure for wells of any azimuth and inclination. Finally, they show how it is possible to estimate the magnitudes of both S{sub h min} and S{sub H max} in cases where independent knowledge of stress orientation is available (for example, from wellbore breakouts in nearby vertical boreholes).

Geologic Evolution of a Pliocene-Pleistocene Salt-Withdrawal Minibasin: Eugene Island Block 330, Offshore Louisiana

The spatial and temporal distributions of reservoir sands are documented within the context of an evolving Pliocene-Pleistocene salt-withdrawal shelf minibasin. The Eugene Island Block 330 field, a giant oil and gas field in offshore Louisiana, is contained within the minibasin. Based on the stratigraphic and structural analyses, we present a sequence-stratigraphic and tectonic-stratigraphic model for reservoir prediction in complex shelf Gulf of Mexico minibasins. The minibasin evolved in three phases: prodelta, proximal deltaic, and fluvial. In the prodelta phase, bathyal and outer neritic shales and turbidites loaded and mobilized an underlying salt sheet. During the proximal deltaic phase, salt continued to withdraw from beneath the minibasin, and lowstand shelf margin deltas remained at a regional fault zone on the northern margin of the minibasin. Sediment accumulation and fault slip rates were high as thick sequences of deltaic sands were deposited adjacent to the fault system. During the final fluvial phase, salt withdrawal waned; consequently, the creation of accommodation space within the minibasin ceased. The basin infilled and, during lowstands, deltaic systems prograded southward. Unconformities developed in the minibasin during the e lowstands. During transgressions, thick packages of shallow-water deltaic and fluvial sands (capped by shales) were deposited on top of the unconformities. One major reservoir, the Lentic, was deposited during the prodelta phase. The hydrocarbons are trapped by deep early faults within this geopressured sand. Most of the major exploited reservoirs of the Block 330 field were deposited in the proximal deltaic phase. Reservoirs deposited in this phase are laterally extensive proximal deltaic sands that have good lateral seals because of the amount of fault activity that occurred in this interval. Only one major reservoir was deposited in the fluvial phase. This reservoir was deposited while the basin-bounding faults were still active, so the reservoir has four-way closure. Sands deposited later in the fluvial phase tend to lack lateral seals and structural closure.